Back-Reaming Rotary Steering

ABSTRACT

A rotary steerable system (RSS) having multiple steering pads, a valve to sequentially actuate the plurality of steering pads, and a back-reaming bit formed by multiple cutting elements carried by each of the steering pads. While rotating the drill string, the RSS, and the drill bit, the valve and/or the controller are operated to sequentially actuate the steering pads to operatively urge the RSS and the drill bit away from a longitudinal axis of the wellbore, thus steering the wellbore drilling direction. Thereafter, while rotating the drill string, the RSS, and the drill bit, the valve and/or the controller are operated to simultaneously actuate each of the steering pads to operatively urge at least one of the cutting elements on each of the steering pads into contact with a sidewall of the wellbore, thus back-reaming the wellbore.

BACKGROUND OF THE DISCLOSURE

Oil and gas wellbore drilling applications may utilize a rotarysteerable system to control the direction of drilling during formationof the wellbore. A rotary steerable system may utilize a drill bit thatis coupled with a drill collar and rotated to drill through thesubterranean formation. One or more valves and control systems maycontrol steering pads selectively actuated for radial deflection tocontrol the direction of drilling. The valve(s) may be held at angularorientations with respect to the rotating drill collar to control theflow of fluid to the steering pads.

Such rotary steerable systems may be utilized in conjunction with aconcentric reamer as part of a bottom-hole assembly (BHA). However, dueat least in part to operational demands of other BHA components, theconcentric reamer is located a considerable distance away from the drillbit. For example, once target depth (TD) is reached, the portion of thewellbore that has not been reamed by the concentric reamer—also known asthe “rathole” portion of the wellbore located between the concentricreamer and the drill bit—may far exceed 100-200 feet (or 30-60 meters).Consequently, to open the rathole to an adequate size, the drill string,BHA, and drill bit are removed so that another tool/tool string can berun in-hole to ream the rathole. Of course, this procedure istime-intensive and expensive.

SUMMARY OF THE DISCLOSURE

The present disclosure introduces a system for drilling a wellbore. Thesystem includes a rotary steerable system (RSS) coupled between a drillstring collar and a drill bit. The RSS includes a housing, multiplesteering pads, a valve, and a controller. The steering pads arecircumferentially spaced around the housing, and are each actuatable toradially extend away from the housing independent of the other steeringpads. At least one of the steering pads comprises a back-reaming bit.The valve and the controller are collectively operable to sequentiallyactuate the steering pads to substantially decentralize the RSS relativeto the wellbore, and simultaneously actuate each steering pad tosubstantially centralize the RSS relative to the wellbore, thus urgingthe back-reaming bit into contact with a sidewall of the wellbore.

The present disclosure also introduces an apparatus that includes adrill string disposed within a wellbore that extends from a wellsitesurface to a subterranean formation. The apparatus also includes a drillbit and a rotary steerable system (RSS) coupled between the drill stringand the drill bit. The RSS includes multiple steering pads spacedcircumferentially apart around a perimeter of the RSS, a valve operableto sequentially actuate the steering pads, and a back-reaming bit thatincludes multiple cutting elements. Each of the steering pads includesat least one of the cutting elements.

The present disclosure also introduces a method in which an apparatus isconveyed within a wellbore that extends from a wellsite surface to asubterranean formation. The apparatus includes a drill string, a drillbit, and at a rotary steerable system (RSS) coupled between the drillstring and the drill bit. The RSS includes multiple steering pads spacedcircumferentially apart around a perimeter of the RSS. Each of thesteering pads carries at least one of a set of cutting elements. The RSSalso includes a valve operable for sequentially actuating the steeringpads, as well as a controller. The method also includes rotating thedrill string, thereby rotating the RSS and the drill bit, whileoperating at least one of the valve and the controller to sequentiallyactuate the steering pads to operatively urge the RSS and the drill bitaway from a longitudinal axis of the wellbore. The method also includesrotating the drill string, thereby rotating the RSS and the drill bit,while operating at least one of the valve and the controller tosimultaneously actuate the steering pads to operatively urge at leastone of the cutting elements on each of the steering pads into contactwith a sidewall of the wellbore.

These and additional aspects of the present disclosure are set forth inthe description that follows, and/or may be learned by a person havingordinary skill in the art by reading the materials herein and/orpracticing the principles described herein. At least some aspects of thepresent disclosure may be achieved via means recited in the attachedclaims

BRIEF DESCRIPTION OF THE DRAWINGS

The present disclosure is understood from the following detaileddescription when read with the accompanying figures. It is emphasizedthat, in accordance with the standard practice in the industry, variousfeatures are not drawn to scale. In fact, the dimensions of the variousfeatures may be arbitrarily increased or reduced for clarity ofdiscussion.

FIG. 1 is a schematic view of at least a portion of apparatus accordingto one or more aspects of the present disclosure.

FIG. 2 is a sectional view of a portion of the apparatus shown in FIG.1.

FIG. 3 is a perspective view of a portion of the apparatus shown in FIG.2.

FIG. 4 is a sectional view of a portion of the apparatus shown in FIG.2.

FIG. 5 is a side view of a portion of the apparatus shown in FIG. 2.

FIG. 6 is a schematic view of at least a portion of a bit profileaccording to one or more aspects of the present disclosure.

FIG. 7 is a schematic view of at least a portion of apparatus accordingto one or more aspects of the present disclosure.

FIG. 8 is a schematic view of at least the apparatus shown in FIG. 7 ina subsequent stage of operation according to one or more aspects of thepresent disclosure.

FIG. 9 is a schematic view of at least the apparatus shown in FIG. 8 ina subsequent stage of operation according to one or more aspects of thepresent disclosure.

FIG. 10 is a flow-chart diagram of at least a portion of a methodaccording to one or more aspects of the present disclosure.

FIG. 11 is a flow-chart diagram of at least a portion of a methodaccording to one or more aspects of the present disclosure.

FIG. 12 is a schematic view of at least a portion of apparatus accordingto one or more aspects of the present disclosure.

DETAILED DESCRIPTION

It is to be understood that the following disclosure provides manydifferent embodiments, or examples, for implementing different featuresof various embodiments. Specific examples of components and arrangementsare described below to simplify the present disclosure. These are, ofcourse, merely examples and are not intended to be limiting. Inaddition, the present disclosure may repeat reference numerals and/orletters in the various examples. This repetition is for simplicity andclarity, and does not in itself dictate a relationship between thevarious embodiments and/or configurations discussed. Moreover, theformation of a first feature over or on a second feature in thedescription that follows may include embodiments in which the first andsecond features are formed in direct contact, and may also includeembodiments in which additional features may be formed interposing thefirst and second features, such that the first and second features maynot be in direct contact.

FIG. 1 is a schematic view of at least a portion of a drilling system 20according to one or more aspects of the present disclosure. The drillingsystem 20 may comprise a BHA 22, which may be coupled to and/orotherwise form a portion of a drill string 24, such as may be utilizedto form a wellbore 26 via directional drilling. The drilling system 20comprises a rotary steerable system (RSS) 28 comprising at least threeradially actuated steering pads 30 (two of which being shown in FIG. 2).The steering pads 30 may be at substantially the same axial positionswithin the RSS 28, as shown in FIG. 1, or one or more of the steeringpads 30 may be axially offset in a direction substantially parallel to alongitudinal axis 60 of the wellbore 26, the RSS 28, and/or the BHA 22.The steering pads 30 may be controlled by and/or in conjunction with acorresponding valve system 32. Each steering pad 30 is operable and/orotherwise actuated to act against a sidewall of the wellbore 26, therebyproviding directional control. The valve system 32 may be positionedwith the steering pads 30 within a drill collar and/or other housing 34of the RSS 28. The housing 34 is directly or indirectly coupled with adrill bit 36, which is rotated to cut through a surrounding rockformation 38 that may be in or proximate a hydrocarbon bearing reservoir40.

Depending on the environment and the operational parameters of thedrilling operation, the drilling system 20 may comprise a variety ofother features. For example, the drill string 24 may comprise additionaldrill collars 42 incorporating various drilling modules, such aslogging-while-drilling (LWD) and/or measurement-while-drilling (MWD)modules 44, among others. The additional drill collars 42 may also orinstead comprise one or more conventional reaming devices, such as aconcentric under-reamer device 15 that may be located proximate anuphole end of the BHA 22.

Various surface systems also may form a part of or otherwise be utilizedin conjunction with the drilling system 20. For example, a drilling rig46 positioned above the wellbore 26 may be utilized in conjunction witha drilling fluid system 48 also positioned at the wellsite. The drillingfluid system 48 is operable to deliver drilling fluid (e.g., “mud”) 50from a drilling fluid tank 52, through tubing 54, and into the drillstring 24. The drilling fluid 50 returns to the wellsite surface 10through an annulus 56 between the drill string 24 and the sidewall ofthe wellbore 26. The return flow may be utilized to remove drillcuttings resulting from operation of drill bit 36. The drilling fluid 50may also be utilized in conjunction with control of the RSS 28, such asin conjunction with control of the valve system 32 and/or the steeringpads 30. For example, in addition to being conducted by an internalpassage of the drill string 24 to the drill bit 36, the drilling fluid50 may also be directed to or otherwise utilized to actuate the valvesystem 32 and/or the steering pads 30. Actuation of the steering pads 30may be controlled by and/or in conjunction with the valve system 32,thereby controlling the drilling direction.

The drilling system 20 may also comprise or otherwise be utilized inconjunction with a surface control system 58. The surface control system58 may be utilized to control communication with the RSS 28 and/or othercomponents of the BHA 22. For example, the surface control system 58 mayreceive data from downhole sensor systems and communicate commands tothe RSS 28 to control actuation of the valve system 32, therebycontrolling the drilling direction. Such control electronics and/orother control apparatus may also or instead be located downhole, perhapsintegral to the RSS 28 and/or other component of the BHA 22, such as mayoperate in conjunction with one or more orientation sensors to controlthe drilling direction. The downhole control electronics may be operableto communicate with the surface control system 58, such as to receivedirectional commands and/or to relay information related to drillingand/or the formation 38 to the surface control system 58.

The RSS 28 may be conveyed and operated within the wellbore 26 via thedrill string 24, as described above. However, the RSS 28 may also orinstead be utilized in conjunction with a mud motor and/or turbine, suchas described below and/or otherwise within the scope of the presentdisclosure. Other means of conveyance and/or fluid delivery, however,may also be utilized in implementations within the scope of the presentdisclosure, such as coiled tubing, casing, and/or other tubular means.

In at least one implementation within the scope of the presentdisclosure, the drilling system 20 does not comprise a reaming componentand/or feature other than that which may be incorporated with thesteering pads 30. That is, while conventional BHAs, drilling systems,and/or other apparatus utilized for directional drilling may include aconcentric reamer and/or other type of reaming component and/or featuredisposed at or near an uphole end of the BHA, the drilling system 20,the BHA 22, and the RSS 28 of the present disclosure may include no suchreaming component and/or feature because, for example, the steering pads30 may instead include reaming features and capabilities. Consequently,the drilling system 20, the BHA 22, and the RSS 28 of the presentdisclosure may be shorter, lighter, less expensive, and/or less complex(whether mechanically, operationally, or otherwise) relative to aconventional drilling system, BHA, and/or RSS.

FIG. 2 is a schematic view of a portion of the RSS 28 shown in FIG. 1.Referring to FIGS. 1 and 2, collectively, the housing 34 comprisesand/or is coupled between the drill bit 36 and an MWD or LWD component44 and/or other component 42 of the BHA 22. For example, the housing 34may comprise upper and lower interfaces 35 and 37, respectively, whichmay couple the RSS 28 between the drill bit 36 an adjacent drill collarand/or other component of the drill string 24. The interfaces 35 and 37may be or comprise industry-standard fittings (such as box-pinconnections), threads, and/or other coupling means. Such coupling may bein conjunction with one or more flexible and/or other interveningcomponents.

A variety of RSS components are carried within internal passages 62 ofthe housing 34, such as may be operable for actuation of the steeringpads 30. In the example implementation(s) described below, each steeringpad 30 may be moved radially outward from the housing 34 by acorresponding piston 64, which may be hydraulically actuated viadrilling fluid 50 metered by the valve system 32. However, hydraulic oiland/or other fluids carried internally with the RSS 28 and/or anothercomponent of the BHA 22 or drill string 24 may also or instead beutilized to activate the steering pads 30.

The valve system 32 may comprise a rotational, spider, barrel, digital,and/or other type of valve 66. The valve 66 may be selectively rotated,digitally actuated, and/or otherwise actuated to direct a portion of thedrilling fluid 50 from the corresponding internal passage 62 to selectedones of the steering pads 30. For example, one or more hydraulic lines68 may communicate drilling fluid 50 from the valve 66 to act againstthe pistons 64 corresponding to the steering pads 30. The housing 34 andthe drill bit 36 rotate during drilling of the wellbore 26, during whichtime the valve 66 may undergo a controlled, relative rotation toselectively deliver the drilling fluid 50 through the correspondinghydraulic line(s) 68 to the corresponding steering pads 30.

The valve 66 may be coupled to or otherwise driven by a shaft 70, whichmay be rotated by a corresponding electric and/or other type of motor72. One or more encoders and/or other sensors 74 may be operativelyengaged with the shaft 70 to monitor the angular orientation of thevalve 66 relative to the housing 34. The valve system 32, and/or anothercomponent of the RSS 28, may also comprise one or more control devices75, such as may comprise and/or operate in conjunction with amicroprocessor and/or other controller 76. The control devices 75 and/orcontrollers 76 may each receive data from the sensors 74 and utilizesuch data and/or other data to control the motor 72. The motor 72 maythus be operable in controlling the angular positioning of the valve 66.One or more of the control devices 75 and/or controllers 76 may alsocommunicate with the surface control system 58, such as to receivecommands and/or relay data. One or more of the control devices 75 and/orcontrollers 76 may also comprise and/or operate in conjunction with oneor more additional components, such as a direction and inclinationpackage containing magnetometers and accelerometers (not shown).

Operational power may be provided to each control device 75, controller76, motor 72, and/or other components of the RSS 28 via one or morepower sources 78, such as may be or comprise batteries (not shown)and/or a turbine 80. Each turbine 80 may comprise and/or operate inconjunction with an alternator 82 driven by rotation of the turbineblades 84, such rotation being in response to the pressurized flow ofthe drilling fluid 50 through the internal passages 62.

One or more components of the valve system 32 and/or other component ofthe RSS 28 may be mounted within a pressure housing 86, such as mayprovide a level of protection against the relatively high pressure ofthe drilling fluid 50 and/or the rigors of the downhole environment. Forexample, the motor 72, sensors 74, control device(s) 75, controller(s)76, and alternator 82 may be disposed within one or more pressurehousings 86. Such pressure housing(s) 86 may be rigidly attached to thehousing 34 via one or more centralizers and/or other members 88 disposedwithin the housing 34. Thus, the pressure housing(s) 86 may rotate withthe housing 34.

Each steering pad 30 may be activated by differential pressure, such asbetween the inside and outside of the housing 34. When a steering pad 30is activated, it pivots and/or otherwise moves away from the RSS 28,ultimately pushing against the sidewall of the wellbore 26, thusdeflecting the corresponding RSS 28 in the opposite direction, andthereby providing the RSS 28 with steering capability. As the housing 34rotates, the valve 66 selectively operates to cause the extension andretraction of the corresponding steering pads 30 by alternatinglypermitting and restricting the flow of drilling fluid 50 through thecorresponding hydraulic line 68 to the corresponding piston 64 behindthe steering pad 30. The steering pads 30 may thus rotate substantiallysimultaneously with the rotation/speed of the bit 36. However, in otherimplementations within the scope of the present disclosure,substantially non-rotating pads may also or instead be utilized.

FIG. 3 is an exploded view of an example implementation of at least aportion of the valve 66, depicting the valve 66 as being disengaged fromthe openings 92 leading to the hydraulic lines 68. Referring to FIGS.1-3, collectively, the valve 66 comprises a valve opening 90 that isrotated via the shaft 70 in response to operation of the motor 72. Thevalve opening 90 may be selectively aligned with selected ports 92 thatare part of and/or rotate with the housing 34. The ports 92 deliverdrilling fluid 50 into hydraulic lines 68 for subsequent communicationto the corresponding steering pads 30. In the example implementationdepicted in FIGS. 1-3, the housing 34 comprises three ports 92 connectedto three steering pads 30 via three hydraulic lines 68. However, otherimplementations within the scope of the present disclosure may includeports 92, steering pads 30, and/or hydraulic lines 68 in other numbers.

The valve opening 90 may be selectively aligned with individual ports 92or combinations of adjacent ports 92. Each valve 66 is selectivelyrotated via the shaft 70 and the motor 72 to bring the valve opening 90into alignment or out of alignment with a selected one or two ports 92.

FIG. 4 is a sectional view of the steering pads 30 carried by thehousing 34, the valve 66, and related components. To facilitate anunderstanding of the angular relationship of the valve opening 90 withrespect to the ports 92, the ports 92 have been labeled as a first port92(1), a second port 92(2), and a third port 92(3), corresponding with afirst steering pad 30(1), a second steering pad 30(2), and a thirdsteering pad 30(3). The ports 92(1-3) and steering pads 30(1-3) areillustrated as positioned substantially at 0°, 120°, and 240°,respectively, around the housing 34. If the valve 66 and the housing 34are both positioned at 0°, then the first port 92(1) is activated by thepressure of drilling fluid 50, but the second port 92(2) and third port92(3) are not activated. If the angle of the housing 34 is substantially0° while the angle of the valve 66 is substantially 60°, then the firstport 92(1) and second port 92(2) are both activated.

The size of the valve opening 90 and each of the ports 92(1-3) may varyaccording to a variety of design parameters. For example, the valveopening 90 may have an angular width of about 90° and each of the ports92(1-3) may have an angular width of about 80°. However, the angularwidths and/or other dimensions of the valve opening 90 and the ports92(1-3) may vary within the scope of the present disclosure. The numberof openings 90, ports 92, and hydraulic lines 68 may also vary withinthe scope of the present disclosure, such as in accord with the numberof steering pads 30 of the RSS 28 (which may also vary within the scopeof the present disclosure).

Referring to FIGS. 1-4, collectively, and as described above, the valvesystem 32 may be operated to sequentially actuate the steering pads 30of the RSS 28 to urge the RSS 28 and, hence, the drill bit 36 away froma longitudinal axis 60 of the wellbore 26. Thus, after creating asubstantially straight section 53 of the wellbore 26, the steering pads30 of the RSS 28 may be operated to create a curved section 29 of thewellbore 26.

That is, a first steering pad 30 of the RSS 28 may be actuated to pivotabout a pivot axis, such as may be defined by pivot pins 47, orotherwise extend away from the housing 34 of the RSS 28 and, thus, pushagainst an azimuthal location 49 of the sidewall of the wellbore 26,thereby urging the RSS 28 in the opposite azimuthal direction (towardthe right-hand side of the page in FIG. 1). The pivot pins 47 and/or thepivot axis may extend substantially parallel to the longitudinal axis 60of the housing 34. At substantially the same time, the other steeringpads are not actuated, but instead remain substantially retractedagainst the housing 34, thereby permitting the RSS 28 to be urged awayfrom the longitudinal axis 60 of the wellbore 26. As the RSS 28continues to rotate in the wellbore 26 (in response to rotation of theBHA 22 and drill string 24), the first actuated steering pad 30 rotatesaway from the azimuthal location 49 and retracts back toward the housing34. Consequently, a second steering pad 30 is actuated to extend awayfrom the housing 34 and, thus, push against the azimuthal location 49 ofthe sidewall of the wellbore 26, thereby continuing to urge the RSS 28in the opposite azimuthal direction (toward the right-hand side of thepage in FIG. 1). At substantially the same time, the other steering padsare not actuated, but instead remain substantially retracted against thehousing 34, thereby permitting the RSS 28 to continue to be urged awayfrom the longitudinal axis 60 of the wellbore 26. This process isrepeated, with the steering pads 30 being sequentially actuated to pushagainst the azimuthal location 49 of the sidewall of the wellbore 26until the goal inclination 27 is achieved.

Thereafter, each of the steering pads 30 may be retracted to drillanother, perhaps substantially straight section 51 of the wellbore 26.However, other control schemes by which the steering pads 30 may becontrolled to achieve the substantially straight section 51 are alsowithin the scope of the present disclosure, including implementations inwhich the steering pads 30 are intermittently actuated to account forminor fluctuations in direction, as well as implementations in which thesteering pads 30 are actuated to maintain the wellbore 26 on atrajectory that is dependent upon a boundary and/or other feature of thesubterranean formation 38 and/or reservoir 40 (e.g., geosteering).

FIG. 4 also depicts optional locking mechanisms 67 that may each beoperable to lock and/or otherwise maintain a corresponding steering pad30 in the extended position. For example, each locking mechanism 67 maycomprise a locking member 69 movable between a locking position, asshown in FIG. 4 with respect to the extended steering pad 30(1), and aretracted position, as shown with respect to the non-extended steeringpads 30(2) and 30(3). Each locking mechanism 67 may also comprise one ormore solenoids, transducers, and/or other actuators 71 operable to movethe corresponding locking member 69 between the locking and retractedpositions. Each locking mechanism 67 may be secured within acorresponding recess 73 of the housing 34, whether via threadedengagement, adhesive, press/interference fit, and/or other means.Furthermore, means for locking the steering pads 30 in positionsextended away from the housing 34 other than the example lockingmechanisms 67 depicted in FIG. 4 are also within the scope of thepresent disclosure. Such implementations may comprise one or more rampsand/or other features that may be temporarily inserted between thesteering pads 30 and the housing 34 to temporarily preventradially-inward motion of the steering pads 30, and/or one or morefeatures that may be temporarily positioned underneath the piston 64 totemporarily prevent radially-inward motion of the piston 64, among otherexamples.

FIG. 5 is a side view of the steering pad 30 shown in FIG. 2. Thesteering pad 30 shown in FIGS. 2 and 5 (and others) comprises aplurality of cutting elements 31 that, when considered collectively,constructively form a back-reaming bit. Each steering pad 30 of the RSS28 may carry one or more of the cutting elements 31. In implementationsin which more than one of the steering pads 30 each carries more thanone of the cutting elements 31, the effective back-reaming bit may beformed by each of the cutting elements 31 carried by each of thesteering pads 30, collectively.

Referring to FIGS. 2 and 5, collectively, each cutting element 31 may bemounted in a corresponding pocket, groove, and/or other recess 33 formedin the corresponding steering pad 30, although other means forassembling the cutting elements 31 to the steering pads 30 are alsowithin the scope of the present disclosure. The recesses 33 may fix thecutting elements 31 in a particular location and orientation. However,one or more of the cutting elements 31 may instead be movable within arecess 33, such as in implementations in which the recess 33 maycomprise a bearing and/or other similar element (not shown), such thatthe cutting element 31 may be coupled to or within the bearing elementin a manner permitting the cutting element 31 to rotate relative to thesteering pad 30.

The cutting elements 31 may be arranged, for example, in a regular orirregular grid pattern along or proximate an uphole end or portion 39 ofa corresponding one of the steering pads 30. However, other arrangementsare also within the scope of the present disclosure. Arranging thecutting elements 31 proximate the uphole end 39 of the correspondingsteering pad 30 may reduce or prevent contact between the cuttingelements 31 and the sidewall of the wellbore when the steering pad 30 isactuated for steering during directional drilling.

For example, referring to FIGS. 1-5, collectively, the back-reaming bitformed by the cutting elements 31 may be operable for back-reaming thewellbore 26 by simultaneously extending each of the steering pads 30away from the housing 34 such that the cutting elements 31 contact thesidewall of the wellbore 26 while the RSS 28 is rotated and the drillstring 24 is retracted from the wellbore 26. For example, inimplementations in which the valve 66 is a rotary valve, the valve 66may be disengaged by axial motion away from the openings of thehydraulic lines 68 leading to the steering pads 130 (such as in thedisengaged arrangement shown in FIG. 3), and/or otherwise allowingdrilling or other working fluid to simultaneously actuate each steeringpad 30 substantially simultaneously. For example, one or more solenoidsand/or other linear actuators of the RSS 28 may be operable for suchdisengagement of the valve 66. Similarly, in implementations in whichthe valve 66 is instead a digital valve, it may be digitally operated tosimultaneously actuate each steering pad 30.

Moreover, by consolidating the cutting elements 31 in or near the upholeends or portions 39 of the steering pads 30, inadvertent contact betweenthe cutting elements 31 and the sidewall of the wellbore 26 may bereduced or even eliminated during directional drilling. That is, duringdirectional drilling, the steering pads 30 may not be simultaneouslydeployed, but are instead sequentially deployed in a manner causingbending of the RSS 28 relative to the wellbore 26. Such bending of theRSS 28 relative to the wellbore 26 induces contact between the downholeends or portions 41 of the steering pads 30, but not the uphole ends orportions 39 of the steering pads 30, such that excessive material is notinadvertently removed from the sidewall of the wellbore 26 during thedirectional drilling.

The cutting elements 31 may each comprise a material having sufficienthardness to cut through the desired formation, cement, scale, and/orother material. For example, the cutting elements 31 may include asubstantially cylindrical substrate 43 comprising tungsten carbideand/or other materials, and a cutting layer 45 comprisingpolycrystalline diamond, polycrystalline cubic boron nitride, othermaterials, or some combination of the foregoing. The cutting elements 31may have a diameter ranging between about five millimeters and about 25millimeters. However, other dimensions are also within the scope of thepresent disclosure. The cutting elements 31 may have the same ordifferent dimensions relative to each other, including dimensions whichmay correspond to industry-standard sizes and/or otherwise.

FIG. 6 is a schematic view of the back-reaming bit as it would appearwith the cutting elements 31 rotated into an aggregated profile view,depicting the positions of each cutting element 31 from each steeringpad 30 as if each steering pad 30 was positioned at the same azimuth atthe same time. Such view also depicts a cutting profile 45 (depicted inFIG. 6 by a heavy dark line) collectively formed by outermost edges ofeach cutting element 31. As described above, the cutting elements 31 maybe located at or near the uphole end or portion 39 of the steering pads30 and not at or near the downhole end or portion 41 of the steeringpads 30. Consequently, when bending of the RSS 28 relative to thewellbore 26 during directional drilling induces contact between thedownhole ends or portions 41 of the steering pads 30, but not the upholeends or portions 39 of the steering pads 30, excessive material is notinadvertently removed from the sidewall of the wellbore 26.

For example, the uphole end or portion 39 of each steering pad 30 thatcomprises the cutting elements 31 may be the upper third (33%) of theaxial length 65 of the steering pad 30, such that the lower two-thirds(67%) of each steering pad 30 does not comprise cutting elements 31.However, other dimensional ranges are also within the scope of thepresent disclosure.

The uphole end or portion 39 of each steering pad 30 that comprises thecutting elements 31 may also be limited to an upper, non-linear portionthereof. For example, as depicted in the example implementation shown inFIG. 6, the uphole end of portion 39 of each steering pad 30 may becurved, arcuate, slanted, tilted, beveled, and/or otherwise non-linearrelative to a middle portion 61 of the steering pad 30. As also shown inFIG. 6, the downhole end or portion 41 of each steering pad 30 may alsobe curved, arcuate, slanted, tilted, beveled, and/or otherwisenon-linear relative to the middle portion 61 of the steering pad 30.

The uphole end or portion 39 of each steering pad 30 that comprises thecutting elements 31 may also be that portion of the steering pad 30 thatfalls within a maximum radius 63 of the steering pad 30 when actuated.For example, the middle portion 61 of the steering pad 30 may have thegreatest radius 63 (with respect to other features of the steering pad30) relative to the longitudinal axis 60 of the RSS 28, and the cuttingelements 31 may not extend beyond that radius 63. That is, the cuttingelements 31 may be flush with or recessed below a gauge surface 57 ofthe steering pad 30. In other implementations, however, the cuttingelements 31 may extend slightly beyond the radius of the middle portion61, such as to provide clearance for the middle portion 61 duringback-reaming, and/or to account for wear of the cutting elements 31after prolonged use. For example, the outermost edges of the cuttingelements 31 may extend beyond the radius 63 of the middle portion 61 byless than about five millimeters.

Although not shown in the figures, the RSS 28 may comprise mechanicalstops and/or other means limiting the maximum extent to which eachsteering pad 30 may be extended away from the housing 34. Such means maybe adjustable and/or otherwise designed to match the effectiveback-reaming diameter of the back-reaming bit constructively formed bythe collective cutting elements 31 with the reaming diameter of anotherreaming component of the BHA 22, such as the concentric under-reamer 15shown in FIG. 1.

FIG. 7 is a simplified view of the RSS 28 shown in FIGS. 1-6, in whichthe valve system 32 and hydraulic lines 68 are simplified for clarity ofthe following description. As described above, the RSS 28 is at leastindirectly coupled between the drill bit 36 and an MWD or LWD component44 and/or other component 42 of the BHA 22, and comprises at least threesteering pads 30 operable to sequentially actuate to “steer” the drillbit 36 during directional drilling. In the example implementationdepicted in FIG. 7, the RSS 28 comprises four circumferentially spacedsteering pads 30, comprising two sets each of two diametrically opposedsteering pads 30 (although one set is hidden from view in FIG. 7).However, other implementations within the scope of the presentdisclosure may not comprise diametrically opposed steering pads 30, andmay comprise more or less than four steering pads 30.

The example RSS 28 depicted in FIG. 7 also comprises a controller 130operable to control the valve system 32 and/or other components of theRSS 28 and/or BHA 22. The controller 130 may comprise one or moreinstances of the control devices 75 and/or controllers 76 shown in FIG.2. The controller 130 may be a single, discrete controller operable tocontrol the valve system 32, such as via control/data lines 132 that mayextend between the controller 130 and the valve system 32. Otherimplementations within the scope of the present disclosure, however, mayutilize multiple controllers 130 each operable to control the valvesystem 32 and/or other components of the RSS 28 and/or BHA 22. Wheremultiple controllers are utilized, two or more (or each) of thecontrollers may be operably connected to a common communication bus. Thecommon or “main” controller may be located somewhere else in the BHA 22,such as in an MWD, LWD, and/or other component 42/44 of the BHA 22. Oneor more of the controllers may also be operable to communicate withother tools of the BHA 22, such as the formation testing tools of MWDand/or LWD modules 44, via a common communication bus. For example, forclosed-loop geosteering, the steering pad controller 130 may be operablein conjunction with formation data obtained by an LWD and/or MWD module44 of the BHA 22, such as to reference a boundary and/or other featureof the formation 38 and/or reservoir 40 (FIG. 1) that may be utilized toguide steering and, thus, the trajectory of the wellbore 26. Thus, amongother possible implementations, the LWD and/or MWD module 44 may beutilized to obtain formation/reservoir image and/or other data that maythen be utilized with the steering pad controller 130 to maintain thedrilling path within a subterranean pay-zone of the formation 38 and/orreservoir 40 while elongating the wellbore 26.

The steering pad controller and/or other downhole controllers 130 of theRSS 28 and/or other portions of the BHA 22 may also communicate withsurface equipment (e.g., the surface control system 58 in FIG. 1) insubstantially real-time manner. For example, such communication may bevia wired drill pipe, electromagnetic (EM) telemetry, and/or others.However, mud pulse telemetry is also contemplated.

FIG. 8 is a schematic exterior view of the apparatus shown in FIG. 7after the controller 130 has operably controlled the valve system 32 toactuate the steering pads 30 of the RSS 28 to operatively urge at leastone of the cutting elements 31 on at least one of the steering pads 30into contact with the sidewall of the wellbore 26, while the drillstring 24, BHA 22, RSS 28 and drill bit 36 continue to rotate. Forexample, such actuation of the steering pads 30 may include actuatingeach of the steering pads 30 simultaneously such that at least one ofthe cutting elements 31 on each of the steering pads 30 contacts thesidewall of the wellbore 26.

Thereafter, the drill string 24 may be retracted from the wellbore 26while the drill string 24, BHA 22, RSS 28 and drill bit 36 continue torotate, as shown in FIG. 9. During such rotating retraction, thecontroller 130 may operably control the valve system 32 to actuate thesteering pads 30 to operatively maintain at least one of the cuttingelements 31 on at least one of the steering pads 30 in contact with thesidewall of the wellbore 26. For example, such actuation of the steeringpads 30 may include actuating each of the steering pads 30simultaneously such that at least one of the cutting elements 31 on eachof the steering pads 30 contacts the sidewall of the wellbore 26.Consequently, the cutting elements 31 contacting the sidewall of thewellbore 26 may be utilized for a back-reaming operation, wherebyundulations, bumps, ridges, protrusions, and/or other irregularities ofthe surface of the wellbore 26 may be reduced, smoothed, and/orpartially or substantially removed. Consequently, the length of theremaining rathole section 55 of the wellbore 26 may be substantiallylimited to axial separation between the end of the drill bit 36 and thecutting elements 31. For example, the rathole section 55 of the wellbore26 may range between about one meter and about five meters, althoughother values are also within the scope of the present disclosure.

The dimensions of various features described above may vary across themyriad implementations within the scope of the present disclosure. Onesuch dimension regards the outer diameter of the effective back-reamingbit constructively formed by the cutting elements 31 collectivelycarried by one or more of the steering pads 30 relative to the outerdiameter of the BHA 22, the RSS 28, and/or the drill bit 36. Forexample, if the outer diameter of the BHA 22, the RSS 28, and/or thedrill bit 36 is about 8.3 inches (or about 21.1 centimeters), then theouter diameter of the back-reaming bit may be about 9.3 inches (or about23.6 centimeters). If the outer diameter of the BHA 22, the RSS 28,and/or the drill bit 36 is about 6.8 inches (or about 17.3 centimeters),then the outer diameter of the back-reaming bit may be about 7.7 inches(or about 19.6 centimeters). If the outer diameter of the BHA 22, theRSS 28, and/or the drill bit 36 is about 4.8 inches (or about 12.2centimeters), then the outer diameter of the back-reaming bit may beabout 5.6 inches (or about 14.2 centimeters). The outer diameter of theback-reaming bit may be greater than the outer diameter of the BHA 22,the RSS 28, and/or the drill bit 36 by an amount ranging between about0.5 inches (or about 1.3 centimeters) and about 1.5 inches (or about 3.8centimeters). Of course, the dimensions described above are examples,and other dimensions are also within the scope of the presentdisclosure.

FIG. 10 is a flow-chart diagram of at least a portion of a method (800)according to one or more aspects of the present disclosure. The method(800) may be executed utilizing at least a portion of the apparatusshown in one or more of FIGS. 1-9, among other apparatus within thescope of the present disclosure. For example, the method (800) maycomprise conveying such apparatus within a wellbore that extends from awellsite surface to a subterranean formation, wherein the wellbore maybe substantially similar to the wellbore 26 shown in one or more ofFIGS. 1, 7, 8, and 9. Such apparatus may comprise or be utilized inconjunction with a drill string, a drill bit, and an RSS collectivelycoupled in series between the drill string and the drill bit, such asthe drill string 24, the drill bit 36, and the RSS 28 shown in one ormore of FIGS. 1-9. The method (800) may comprise coupling (810) the RSS,and perhaps other portions of a BHA (such as the BHA 22 shown in one ormore of FIGS. 1-9), between the drill string and the drill bit.

As described above, the RSS may comprise at least three steering padsspaced circumferentially apart around a perimeter of the RSS, a valveoperable to sequentially actuate the steering pads, a controlleroperable to control the valve, and a plurality of cutting elementscarried by one or more of the steering pads. The steering pads may besubstantially similar to those shown in one or more of FIGS. 1, 2, and4-8. The rotational valve may be substantially similar to at least aportion of the valve systems 32 shown in one or more of FIGS. 1-9. Thecontroller may be substantially similar to the surface control system 58shown in FIG. 1, the controller 75 and/or the processor 76 shown in FIG.2, and/or the controller 130 shown in FIG. 7. The cutting elements maybe substantially similar to those shown in one or more of FIGS. 2 and5-9.

The method (800) comprises operating (820) the drill string, the RSS,and the drill bit to create a first wellbore section having a firsttrajectory. For example, such operation (820) may comprise rotating thedrill string, and thereby rotating the RSS and the drill bit, whileoperating at least one of the valve and the controller to sequentiallyand/or otherwise actuate the steering pads to operatively urge the RSSand drill bit relative to a longitudinal axis of the wellbore to achievethe intended trajectory of the first wellbore section. The firstwellbore section may be substantially similar to the wellbore section 53or the wellbore section 29 shown in FIG. 1.

The method (800) also comprises operating (830) the drill string, theRSS, and the drill bit to create a second wellbore section having asecond trajectory. For example, such operation (830) may compriserotating the drill string, and thereby rotating the RSS and the drillbit, while operating at least one of the valve and the controller tosequentially and/or otherwise actuate the steering pads to operativelyurge the RSS and drill bit relative to a longitudinal axis of thewellbore to achieve the intended trajectory of the second wellboresection. The second wellbore section may be substantially similar to thewellbore section 29 or the wellbore section 51 shown in FIG. 1. Forexample, if the first operation (820) resulted in the substantiallystraight wellbore section 53 shown in FIG. 1, then the second operation(830) may result in the curved wellbore section 29 shown in FIG. 1.Similarly, if the first operation (820) resulted in the curved wellboresection 29 shown in FIG. 1, then the second operation (830) may resultin the substantially straight wellbore section 51 shown in FIG. 1.However, as described above, either or both of the first and secondwellbore sections may have trajectories other than as shown in FIG. 1,including trajectories following, paralleling, and/or otherwisecorresponding to a boundary and/or other feature of a subterraneanformation or reservoir (e.g., geosteering), among other examples withinthe scope of the present disclosure.

Rotating the drill string while operating at least one of the valve andthe controller to sequentially actuate the steering pads to operativelyurge the RSS and the drill bit relative to the longitudinal axis of thewellbore may comprise rotating the drill string while operating at leastone of the valve and the controller to sequentially actuate the steeringpads to operatively urge the RSS and the drill bit in a first azimuthaldirection away from the longitudinal axis of the wellbore. In suchimplementations, among others, the method (800) may also compriserotating the drill string while operating at least one of the valve andthe controller to sequentially actuate the steering pads to operativelyurge the RSS and the drill bit in a second azimuthal direction away fromthe longitudinal axis of the wellbore. For example, the first and secondazimuthal directions may differ by at least about twenty degrees. Thefirst and second azimuthal directions may be substantially opposite eachother, such as in implementations in which the first and secondazimuthal directions differ by an amount ranging between about 170degrees and about 190 degrees.

The method (800) also comprises operating (840) the drill string and theRSS to back-ream the second wellbore section. For example, suchoperation (840) may comprise rotating the drill string, and therebyrotating the RSS and the drill bit, while operating at least one of thevalve and the controller to simultaneously actuate each of the steeringpads to operatively urge at least one of the cutting elements on atleast one of the steering pads into contact with the sidewall of thewellbore. The operation (840) may comprise operating at least one of thevalve and the controller to simultaneously actuate each of the steeringpads to operatively urge at least one of the cutting elements on each ofthe steering pads into substantially simultaneous contact with thesidewall of the wellbore. The operation (840) may also comprise lockingone or more of the steering pads in the extended position, such as viaoperation of the locking mechanisms 67 shown in FIG. 4 and/or otherlocking means, and may also comprise immediately or otherwise thereafterunlocking the steering pads to permit the steering pads to again retracttowards the RSS housing. The resulting, back-reamed wellbore mayresemble that shown in FIG. 9, in which the rathole section of thewellbore is limited to the distance by which the drill bit and thecutting elements are axially separated.

The method (800) also comprises operating (850) the drill string and theRSS to back-ream the first wellbore section. For example, such operation(850) may comprise rotating the drill string, and thereby rotating theRSS and the drill bit, while operating at least one of the valve and thecontroller to simultaneously actuate each of the steering pads tooperatively urge at least one of the cutting elements on each of thesteering pads into contact with the sidewall of the wellbore. Theoperation (850) may also comprise locking one or more of the steeringpads in the extended position, such as via operation of the lockingmechanisms 67 shown in FIG. 4 and/or other locking means, and may alsocomprise immediately or otherwise thereafter unlocking the steering padsto permit the steering pads to again retract towards the RSS housing.

FIG. 11 is a flow-chart diagram of at least a portion of a method (900)according to one or more aspects of the present disclosure. The method(900) may be executed utilizing at least a portion of the apparatusshown in one or more of FIGS. 1-9, among other apparatus within thescope of the present disclosure. For example, the method (900) maycomprise conveying such apparatus within a wellbore that extends from awellsite surface to a subterranean formation, wherein the wellbore maybe substantially similar to the wellbore 26 shown in one or more ofFIGS. 1, 7, 8, and 9. Such apparatus may comprise or be utilized inconjunction with a drill string, a drill bit, and an RSS collectivelycoupled in series between the drill string and the drill bit, such asthe drill string 24, the drill bit 36, and the RSS 28 shown in one ormore of FIGS. 1-9. The method (900) may comprise coupling (910) the RSS,and perhaps other portions of a BHA (such as the BHA shown in one ormore of FIGS. 1-9), between the drill string and the drill bit.

As described above, the RSS may comprise at least three steering padsspaced circumferentially apart around a perimeter of the RSS, a valveoperable to sequentially actuate the steering pads, a controlleroperable to control the valve, and a plurality of cutting elementscarried by one or more of the steering pads. The steering pads may besubstantially similar to those shown in one or more of FIGS. 1, 2, and4-9. The rotational valve may be substantially similar to at least aportion of the valve systems 32 shown in one or more of FIGS. 1-9. Thecontroller may be substantially similar to the surface control system 58shown in FIG. 1, the controller 75 and/or the processor 76 shown in FIG.2, and/or the controller 130 shown in FIG. 7. The cutting elements maybe substantially similar to those shown in one or more of FIGS. 2 and5-9.

The method (900) comprises operating (920) the drill string, the RSS,and the drill bit to create a first wellbore section having a firsttrajectory. For example, such operation (920) may comprise rotating thedrill string, and thereby rotating the RSS and the drill bit, whileoperating at least one of the valve and the controller to sequentiallyand/or otherwise actuate the steering pads to operatively urge the RSSand drill bit relative to a longitudinal axis of the wellbore to achievethe intended trajectory of the first wellbore section. The firstwellbore section may be substantially similar to the wellbore section 53or the wellbore section 29 shown in FIG. 1.

The method (900) also comprises operating (930) the drill string and theRSS to back-ream the first wellbore section. For example, such operation(930) may comprise rotating the drill string, and thereby rotating theRSS and the drill bit, while operating at least one of the valve and thecontroller to simultaneously actuate each of the steering pads tooperatively urge at least one of the cutting elements on at least one ofthe steering pads into contact with the sidewall of the wellbore. Theoperation (930) may comprise operating at least one of the valve and thecontroller to simultaneously actuate each of the steering pads tooperatively urge at least one of the cutting elements on each of thesteering pads into substantially simultaneous contact with the sidewallof the wellbore. The operation (930) may also comprise locking one ormore of the steering pads in the extended position, such as viaoperation of the locking mechanisms 67 shown in FIG. 4 and/or otherlocking means, and may also comprise immediately or otherwise thereafterunlocking the steering pads to permit the steering pads to again retracttowards the RSS housing.

The method (900) may also comprise installing (940) a casing in thefirst wellbore section after the back-reaming operation (930). Forexample, the operation (920) performed to create the first wellboresection may result in the wellbore section 53 shown in FIG. 1, and theinstalled (940) casing may be substantially similar to the casing 59shown in FIG. 1. Installing (940) the casing may comprise positioningcasing in the back-reamed first wellbore section, and then securing thepositioned casing in place by cement and/or coupling the casing topreviously installed casing, among other installation methods within thescope of the present disclosure. Installing (940) the casing in theback-reamed first wellbore section may be performed with or withoutremoving the drill string from the wellbore.

The method (900) also comprises operating (950) the drill string, theRSS, and the drill bit to create a second wellbore section having asecond trajectory. For example, such operation (950) may compriserotating the drill string, and thereby rotating the RSS and the drillbit, while operating at least one of the valve and the controller tosequentially and/or otherwise actuate the steering pads to operativelyurge the RSS and drill bit relative to a longitudinal axis of thewellbore to achieve the intended trajectory of the second wellboresection. The second wellbore section may be substantially similar to thewellbore section 29 or the wellbore section 51 shown in FIG. 1. Forexample, if the first operation (920) resulted in the substantiallystraight wellbore section 53 shown in FIG. 1, then the second operation(950) may result in the curved wellbore section 29 shown in FIG. 1.Similarly, if the first operation (920) resulted in the curved wellboresection 29 shown in FIG. 1, then the second operation (950) may resultin the substantially straight wellbore section 51 shown in FIG. 1.However, as described above, either or both of the first and secondwellbore sections may have trajectories other than as shown in FIG. 1,including trajectories following, paralleling, and/or otherwisecorresponding to a boundary and/or other feature of a subterraneanformation or reservoir (e.g., geosteering), among other examples withinthe scope of the present disclosure.

The method (900) also comprises operating (960) the drill string and theRSS to back-ream the second wellbore section. For example, suchoperation (960) may comprise rotating the drill string, and therebyrotating the RSS and the drill bit, while operating at least one of thevalve and the controller to simultaneously actuate each of the steeringpads to operatively urge at least one of the cutting elements on atleast one of the steering pads into contact with the sidewall of thewellbore. The operation (960) may comprise operating at least one of thevalve and the controller to simultaneously actuate each of the steeringpads to operatively urge at least one of the cutting elements on each ofthe steering pads into substantially simultaneous contact with thesidewall of the wellbore. The operation (960) may also comprise lockingone or more of the steering pads in the extended position, such as viaoperation of the locking mechanisms 67 shown in FIG. 4 and/or otherlocking means, and may also comprise immediately or otherwise thereafterunlocking the steering pads to permit the steering pads to again retracttowards the RSS housing. The resulting, back-reamed wellbore mayresemble that shown in FIG. 9, in which the rathole section of thewellbore is limited to the distance by which the drill bit and thecutting elements are axially separated.

The method (900) may also comprise installing (970) a casing in thesecond wellbore section after the back-reaming operation (960).Installing (970) the casing may comprise positioning casing in theback-reamed second wellbore section, and then securing the positionedcasing in place by cement and/or coupling the casing to previouslyinstalled (940) casing, among other installation methods within thescope of the present disclosure. Installing (970) the casing in theback-reamed second wellbore section may be performed with or withoutremoving the drill string from the wellbore.

Methods within the scope of the present disclosure may also compriseconventional back-reaming that is performed in addition to theback-reaming described above. For example, such conventionalback-reaming may utilize the drill bit to clean the borehole, includingimplementations in which the conventional back-reaming does notsubstantially enlarge the borehole diameter. Such implementations mayentail maintaining each of the steering pads retracted against thehousing of the RSS via corresponding actuation (or lack thereof) of thedigital or rotary valves.

FIG. 12 is a schematic view of at least a portion of apparatus accordingto one or more aspects of the present disclosure. The apparatus is orcomprises a processing system 1300 that may execute examplemachine-readable instructions to implement at least a portion of one ormore of the methods and/or processes described herein, and/or toimplement a portion of one or more of the example RSS and/or otherdownhole tools described herein. The processing system 1300 may be orcomprise, for example, one or more processors, controllers,special-purpose computing devices, servers, personal computers, personaldigital assistant (“PDA”) devices, smartphones, internet appliances,and/or other types of computing devices. Moreover, while it is possiblethat the entirety of the processing system 1300 shown in FIG. 12 isimplemented within downhole apparatus, perhaps as at least a portion ofthe control devices 75, controllers 76, controller 130, other downholeapparatus shown in one or more of FIGS. 1-9, and/or other downholeapparatus, it is also contemplated that one or more components orfunctions of the processing system 1300 may be implemented in wellsitesurface equipment, perhaps including the surface control system 58depicted in FIG. 1 and/or other surface equipment.

The processing system 1300 may comprise a processor 1312 such as, forexample, a general-purpose programmable processor. The processor 1312may comprise a local memory 1314, and may execute coded instructions1332 present in the local memory 1314 and/or another memory device. Theprocessor 1312 may execute, among other things, machine-readableinstructions or programs to implement the methods and/or processesdescribed herein. The programs stored in the local memory 1314 mayinclude program instructions or computer program code that, whenexecuted by an associated processor, enable surface equipment and/ordownhole controller and/or control system to perform tasks as describedherein. The processor 1312 may be, comprise, or be implemented by one ora plurality of processors of various types suitable to the localapplication environment, and may include one or more of general-purposecomputers, special-purpose computers, microprocessors, digital signalprocessors (“DSPs”), field-programmable gate arrays (“FPGAs”),application-specific integrated circuits (“ASICs”), and processors basedon a multi-core processor architecture, as non-limiting examples. Ofcourse, other processors from other families are also appropriate.

The processor 1312 may be in communication with a main memory, such asmay include a volatile memory 1318 and a non-volatile memory 1320,perhaps via a bus 1322 and/or other communication means. The volatilememory 1318 may be, comprise, or be implemented by random access memory(RAM), static random access memory (SRAM), synchronous dynamic randomaccess memory (SDRAM), dynamic random access memory (DRAM), RAMBUSdynamic random access memory (RDRAM) and/or other types of random accessmemory devices. The non-volatile memory 1320 may be, comprise, or beimplemented by read-only memory, flash memory and/or other types ofmemory devices. One or more memory controllers (not shown) may controlaccess to the volatile memory 1318 and/or the non-volatile memory 1320.

The processing system 1300 may also comprise an interface circuit 1324.The interface circuit 1324 may be, comprise, or be implemented byvarious types of standard interfaces, such as an Ethernet interface, auniversal serial bus (USB), a third generation input/output (3GIO)interface, a wireless interface, and/or a cellular interface, amongothers. The interface circuit 1324 may also comprise a graphics drivercard. The interface circuit 1324 may also comprise a communicationdevice such as a modem or network interface card to facilitate exchangeof data with external computing devices via a network (e.g., Ethernetconnection, digital subscriber line (“DSL”), telephone line, coaxialcable, cellular telephone system, satellite, etc.).

One or more input devices 1326 may be connected to the interface circuit1324. The input device(s) 1326 may permit a user to enter data andcommands into the processor 1312. The input device(s) 1326 may be,comprise, or be implemented by, for example, a keyboard, a mouse, atouchscreen, a track-pad, a trackball, an isopoint, and/or a voicerecognition system, among others.

One or more output devices 1328 may also be connected to the interfacecircuit 1324. The output devices 1328 may be, comprise, or beimplemented by, for example, display devices (e.g., a liquid crystaldisplay or cathode ray tube display (CRT), among others), printers,and/or speakers, among others.

The processing system 1300 may also comprise one or more mass storagedevices 1330 for storing machine-readable instructions and data.Examples of such mass storage devices 1330 include floppy disk drives,hard drive disks, compact disk (CD) drives, and digital versatile disk(DVD) drives, among others. The coded instructions 1332 may be stored inthe mass storage device 1330, the volatile memory 1318, the non-volatilememory 1320, the local memory 1314, and/or on a removable storage medium1334, such as a CD or DVD. Thus, the modules and/or other components ofthe processing system 1300 may be implemented in accordance withhardware (embodied in one or more chips including an integrated circuitsuch as an application specific integrated circuit), or may beimplemented as software or firmware for execution by a processor. Inparticular, in the case of firmware or software, the embodiment can beprovided as a computer program product including a computer readablemedium or storage structure embodying computer program code (i.e.,software or firmware) thereon for execution by the processor.

In view of the entirety of the present disclosure, including the figuresand the claims that follow, a person having ordinary skill in the artwill readily recognize that the present disclosure introduces a systemfor drilling a wellbore, wherein the system comprises: a rotarysteerable system (RSS) at least indirectly coupled between a drillstring collar and a drill bit, wherein the RSS comprises: a housing; aplurality of steering pads circumferentially spaced around the housing,wherein each of the plurality of steering pads is actuatable to radiallyextend away from the housing independent of the other ones of theplurality of steering pads, and wherein at least one of the plurality ofsteering pads comprises a back-reaming bit; a valve; and a controller,wherein the valve and the controller are collectively operable to:sequentially actuate ones of the plurality of steering pads tosubstantially decentralize the RSS relative to the wellbore; andsimultaneously actuate each of the plurality of steering pads tosubstantially centralize the RSS relative to the wellbore, thus urgingthe back-reaming bit into contact with a sidewall of the wellbore.

Each of the plurality of steering pads may be actuatable to radiallyextend away from the housing by rotating about an axis that issubstantially parallel to a longitudinal axis of the housing.

The valve may be a digital valve.

The valve may be a rotational valve. The valve and the controller may becollectively operable to simultaneously actuate each of the plurality ofsteering pads by disengaging the valve.

The back-reaming bit may comprise a plurality of cutting elements. Eachof the plurality of cutting elements may comprise: a substrate coupledto the corresponding steering pad; and a cutting layer coupled to thesubstrate. The substrate may substantially comprise tungsten carbide.The cutting layer may substantially comprise polycrystalline diamond.Each of the plurality of steering pads may comprise at least one of theplurality of cutting elements. Simultaneously actuating each of theplurality of steering pads to substantially centralize the RSS relativeto the wellbore may urge at least one of the plurality of cuttingelements on each of the plurality of steering pads into contact with thesidewall of the wellbore.

Each of the plurality of steering pads may be actuatable to radiallyextend away from a retracted position toward an extended position. Eachof the plurality of steering pads may be lockable in the extendedposition.

The cutting elements may be disposed in an uphole portion of each of theplurality of steering pads and not in a downhole portion of each of theplurality of steering pads.

The present disclosure also introduces an apparatus comprising: a drillstring disposed within a wellbore that extends from a wellsite surfaceto a subterranean formation; a drill bit; and a rotary steerable system(RSS) coupled between the drill string and the drill bit, wherein theRSS comprises: a plurality of steering pads spaced circumferentiallyapart around a perimeter of the RSS; a valve operable to sequentiallyactuate the plurality of steering pads; and a back-reaming bitcomprising a plurality of cutting elements, wherein each of theplurality of steering pads comprises at least one of the plurality ofcutting elements.

Each of the plurality of cutting elements may comprise: a substratecoupled to a corresponding one of the plurality of steering pads; and acutting layer coupled to the substrate. The substrate may substantiallycomprise tungsten carbide. The cutting layer may substantially comprisepolycrystalline diamond.

The apparatus may further comprise a controller, wherein the valve andthe controller may be collectively operable to sequentially actuate theplurality of steering pads to operatively urge the RSS away from alongitudinal axis of the wellbore. The valve and the controller may becollectively further operable to simultaneously actuate each of theplurality of steering pads to operatively urge at least one of theplurality of cutting elements on each of the plurality of steering padsinto contact with a sidewall of the wellbore.

The apparatus may not comprise a reaming tool, component, or featuredisposed between the drill string and the RSS.

The apparatus may not comprise a reaming tool, component, or featuredisposed between the drill string and the drill bit, other than theback-reaming bit formed by the plurality of cutting elements comprisedby corresponding ones of the plurality of steering pads.

The present disclosure also introduces a method comprising: conveyingapparatus within a wellbore that extends from a wellsite surface to asubterranean formation, wherein the apparatus comprises a drill string,a drill bit, and at a rotary steerable system (RSS) coupled between thedrill string and the drill bit, and wherein the RSS comprises: aplurality of steering pads spaced circumferentially apart around aperimeter of the RSS, wherein each of the plurality of steering padscarries at least one of a plurality of cutting elements; a valveoperable for sequentially actuating the steering pads; and a controller;rotating the drill string, thereby rotating the RSS and the drill bit,while operating at least one of the valve and the controller tosequentially actuate the plurality of steering pads to operatively urgethe RSS and the drill bit away from a longitudinal axis of the wellbore;and rotating the drill string, thereby rotating the RSS and the drillbit, while operating at least one of the valve and the controller tosimultaneously actuate each of the plurality of steering pads tooperatively urge at least one of the plurality of the cutting elementson each of the plurality of steering pads into contact with a sidewallof the wellbore.

The method may further comprise, prior to conveying at least a portionof the apparatus within the wellbore, coupling the RSS between the drillstring and the drill bit.

Rotating the drill string while operating at least one of the valve andthe controller to sequentially actuate the plurality of steering pads tooperatively urge the RSS and the drill bit away from a longitudinal axisof the wellbore may comprise rotating the drill string while operatingat least one of the valve and the controller to sequentially actuate theplurality of steering pads to operatively urge the RSS and the drill bitin a first azimuthal direction away from the longitudinal axis of thewellbore. In such implementations, the method may further comprise:rotating the drill string while operating at least one of the valve andthe controller to sequentially actuate the plurality of steering pads tooperatively urge the RSS and the drill bit in a second azimuthaldirection away from the longitudinal axis of the wellbore. The first andsecond azimuthal directions may differ by at least about twenty degrees.The first and second azimuthal directions may be substantially oppositeeach other. The first and second azimuthal directions may differ by anamount ranging between about 170 degrees and about 190 degrees. Rotatingthe drill string while operating at least one of the valve and thecontroller to sequentially actuate the plurality of steering pads tooperatively urge the RSS and the drill bit in the first azimuthaldirection away from the longitudinal axis of the wellbore may create afirst wellbore section extending in a first wellbore direction. Rotatingthe drill string while operating at least one of the valve and thecontroller to sequentially actuate the plurality of steering pads tooperatively urge the RSS and the drill bit in the second azimuthaldirection away from the longitudinal axis of the wellbore may create asecond wellbore section extending in a second wellbore direction.Rotating the drill string while operating at least one of the valve andthe controller to simultaneously actuate each of the plurality ofsteering pads to operatively urge at least one of the plurality of thecutting elements on each of the plurality of steering pads into contactwith the sidewall of the wellbore may include back-reaming the first andsecond wellbore sections. The second wellbore section may be createdafter the first wellbore section is created. The second wellbore sectionmay be back-reamed before the first wellbore section is back-reamed.

The foregoing outlines features of several embodiments so that a personhaving ordinary skill in the art may better understand the aspects ofthe present disclosure. A person having ordinary skill in the art shouldappreciate that they may readily use the present disclosure as a basisfor designing or modifying other processes and structures for carryingout the same goals and/or achieving the same aspects of theimplementations introduced herein. A person having ordinary skill in theart should also realize that such equivalent constructions do not departfrom the scope of the present disclosure, and that they may make variouschanges, substitutions and alterations herein without departing from thespirit and scope of the present disclosure.

The Abstract at the end of this disclosure is provided to comply with 37C.F.R. §1.72(b) to allow the reader to quickly ascertain the nature ofthe technical disclosure. It is submitted with the understanding that itwill not be used to interpret or limit the scope or meaning of theclaims.

What is claimed is:
 1. A system for drilling a wellbore, comprising: arotary steerable system (RSS) at least indirectly coupled between adrill string collar and a drill bit, wherein the RSS comprises: ahousing; a plurality of steering pads circumferentially spaced aroundthe housing, wherein each of the plurality of steering pads isactuatable to radially extend away from the housing independent of theother ones of the plurality of steering pads, and wherein at least oneof the plurality of steering pads comprises a back-reaming bit; a valve;and a controller, wherein the valve and the controller are collectivelyoperable to: sequentially actuate ones of the plurality of steering padsto substantially decentralize the RSS relative to the wellbore; andsimultaneously actuate each of the plurality of steering pads tosubstantially centralize the RSS relative to the wellbore, thus urgingthe back-reaming bit into contact with a sidewall of the wellbore. 2.The system of claim 1 wherein each of the plurality of steering pads isactuatable to radially extend away from the housing by rotating about anaxis that is substantially parallel to a longitudinal axis of thehousing.
 3. The system of claim 1 wherein the valve and the controllerare collectively operable to simultaneously actuate each of theplurality of steering pads by disengaging the valve.
 4. The system ofclaim 1 wherein the back-reaming bit comprises a plurality of cuttingelements.
 5. The system of claim 4 wherein each of the plurality ofcutting elements comprises: a substrate coupled to the correspondingsteering pad; and a cutting layer coupled to the substrate.
 6. Thesystem of claim 4 wherein each of the plurality of steering padscomprises at least one of the plurality of cutting elements.
 7. Thesystem of claim 6 wherein simultaneously actuating each of the pluralityof steering pads to substantially centralize the RSS relative to thewellbore urges at least one of the plurality of cutting elements on eachof the plurality of steering pads into contact with the sidewall of thewellbore.
 8. The system of claim 1 wherein each of the plurality ofsteering pads is actuatable to radially extend away from a retractedposition toward an extended position.
 9. The system of claim 8 whereineach of the plurality of steering pads is lockable in the extendedposition.
 10. The system of claim 1 wherein the cutting elements aredisposed in an uphole portion of each of the plurality of steering padsand not in a downhole portion of each of the plurality of steering pads.11. An apparatus, comprising: a drill string disposed within a wellborethat extends from a wellsite surface to a subterranean formation; adrill bit; and a rotary steerable system (RSS) coupled between the drillstring and the drill bit, wherein the RSS comprises: a plurality ofsteering pads spaced circumferentially apart around a perimeter of theRSS; a valve operable to sequentially actuate the plurality of steeringpads; and a back-reaming bit comprising a plurality of cutting elements,wherein each of the plurality of steering pads comprises at least one ofthe plurality of cutting elements.
 12. The apparatus of claim 11 whereineach of the plurality of cutting elements comprises: a substrate coupledto a corresponding one of the plurality of steering pads; and a cuttinglayer coupled to the substrate.
 13. The apparatus of claim 12 wherein:the substrate substantially comprises tungsten carbide; and the cuttinglayer substantially comprises polycrystalline diamond.
 14. The apparatusof claim 11 further comprising a controller, wherein the valve and thecontroller are collectively operable to sequentially actuate theplurality of steering pads to operatively urge the RSS away from alongitudinal axis of the wellbore.
 15. The apparatus of claim 14 whereinthe valve and the controller are collectively further operable tosimultaneously actuate each of the plurality of steering pads tooperatively urge at least one of the plurality of cutting elements oneach of the plurality of steering pads into contact with a sidewall ofthe wellbore.
 16. The apparatus of claim 11 not comprising a reamingtool, component, or feature disposed between the drill string and theRSS.
 17. The apparatus of claim 11 not comprising a reaming tool,component, or feature disposed between the drill string and the drillbit, other than the back-reaming bit formed by the plurality of cuttingelements comprised by corresponding ones of the plurality of steeringpads.
 18. A method, comprising: conveying apparatus within a wellborethat extends from a wellsite surface to a subterranean formation,wherein the apparatus comprises a drill string, a drill bit, and at arotary steerable system (RSS) coupled between the drill string and thedrill bit, and wherein the RSS comprises: a plurality of steering padsspaced circumferentially apart around a perimeter of the RSS, whereineach of the plurality of steering pads carries at least one of aplurality of cutting elements; a valve operable for sequentiallyactuating the steering pads; and a controller; rotating the drillstring, thereby rotating the RSS and the drill bit, while operating atleast one of the valve and the controller to sequentially actuate theplurality of steering pads to operatively urge the RSS and the drill bitaway from a longitudinal axis of the wellbore; and rotating the drillstring, thereby rotating the RSS and the drill bit, while operating atleast one of the valve and the controller to simultaneously actuate eachof the plurality of steering pads to operatively urge at least one ofthe plurality of the cutting elements on each of the plurality ofsteering pads into contact with a sidewall of the wellbore.
 19. Themethod of claim 18 wherein: rotating the drill string while operating atleast one of the valve and the controller to sequentially actuate theplurality of steering pads to operatively urge the RSS and the drill bitaway from a longitudinal axis of the wellbore comprises: rotating thedrill string while operating at least one of the valve and thecontroller to sequentially actuate the plurality of steering pads tooperatively urge the RSS and the drill bit in a first azimuthaldirection away from the longitudinal axis of the wellbore; and themethod further comprises: rotating the drill string while operating atleast one of the valve and the controller to sequentially actuate theplurality of steering pads to operatively urge the RSS and the drill bitin a second azimuthal direction away from the longitudinal axis of thewellbore, wherein the first and second azimuthal directions differ by atleast about twenty degrees.
 20. The method of claim 19 wherein: rotatingthe drill string while operating at least one of the valve and thecontroller to sequentially actuate the plurality of steering pads tooperatively urge the RSS and the drill bit in the first azimuthaldirection away from the longitudinal axis of the wellbore creates afirst wellbore section extending in a first wellbore direction; rotatingthe drill string while operating at least one of the valve and thecontroller to sequentially actuate the plurality of steering pads tooperatively urge the RSS and the drill bit in the second azimuthaldirection away from the longitudinal axis of the wellbore creates asecond wellbore section extending in a second wellbore direction; androtating the drill string while operating at least one of the valve andthe controller to simultaneously actuate each of the plurality ofsteering pads to operatively urge at least one of the plurality of thecutting elements on each of the plurality of steering pads into contactwith the sidewall of the wellbore includes back-reaming the first andsecond wellbore sections.